The demand for crude oil has exceeded the existing production in the United States for more than 30 years. This has led to increasing demand for more imported oil and a dependency on foreign suppliers. The growth of emerging economies is rapidly increasing the demand for oil in the global market. It has been estimated that more than half of all conventional oil (oil that can be produced with current technology) has been produced. Most of the remaining conventional oil is located in the Eastern Hemisphere or in environmentally sensitive areas such as the North Pole. The lack of conventional oil supplies could keep oil prices so high that oil dependent nations such as the United States would be unable to fund the development of alternative energy technologies and be forced into dependency on foreign alternative energy as well. Therefore any new technology that could increase the efficiency of oil recovery would be of great benefit to countries such as the U.S. that have large amounts of unrecoverable oil in place (OIP) in older exiting oil fields.
Most petroleum is found in sandstone, siltstone or carbonate. Porosities vary from 5% to 30%. The porous rock, covered with an impermeable layer, collects oil from organic matter in lower source rock. It is a process that takes millions of years. The maturation process converts it to a complex mixture of hydrocarbons of about 82 to 87% carbon and 12 to 15% hydrogen. The oil moves into the porous rock in low concentrations with water. To become a reservoir the porous rock must have some type of impermeable cap-rock that traps the oil. Most traps are anticlinal upfolds of strata that are oval shape, however, fault-traps and salt-domes are also common. Oil near the surface often encounters descending meteoric water that brings in oxygen and bacteria that degrade the oil to heavy oil or tar. Oil is usually not found below 4,900 meters because the high temperature of deep rock will degrade the petroleum into natural gas. Therefore, most oil is less than 4,900 m deep.
Unlike natural gas, the recovery of petroleum oil is not efficient. The existing conventional oil production technologies are able to recover only about one-half of the oil originally in place in a reservoir of light oil. For heavy oil, the recovery is often less than 10%. Tar sands are so heavy that they will not flow at all and no oil can be recovered by conventional drilling and pumping. A technology that could recover a greater percentage of this residual oil could increase oil production from existing reservoirs and reduce the need of the U.S. to imported oil. The additional oil recovered from existing oil producing reservoirs could reduce the need to explore and develop wilderness areas that are potential new oil fields. This additional recovery of existing oil could bridge the gap needed for the development of alternative renewable energy sources.
The Original Oil In Place (OOIP) is the petroleum present in the oil reservoir when first discovered. The volume of the reservoir is determined by the size and porosity of the carbonate or sand stone. The porosity of the rock is a measure of the amount of small chambers or micro-traps within the rock that can hold water or oil. The oil is generally pushed up to the surface with the existing oil reservoir pressures at first. The pressure in the oil well drops with time and there is a need to create overpressure with other means such as water injection or a gas injection for secondary recovery of the OOIP. The choice of a specific secondary recovery technique depends on the type of the hydrocarbon accumulation and the nature of the reservoir. Water injection or “water sweep” or “waterflooding” is a common secondary recovery technique. In waterflooding, pressurized water is injected into the oil-bearing formation rock. Ideally, the injected water displaces the residual oil and moves it to a producing well. Generally in waterflooding, crude oil free of water is recovered first, and then subsequently a mixture of crude oil and water are recovered from the production wells. At some point, the percentage of water in the oil-water mixture (referred to as the water cut) from this technique becomes so high that it is uneconomical to continue pumping oil from the well. The problem, with using water as a “drive fluid”, is that water and oil are immiscible. The lower viscosity water will flow over the oil and by-pass large amounts of oil. Therefore, even after secondary recovery, a significant portion of crude oil remains in the formation, in some cases up to 75% of the OOIP.
Highly fractured reservoirs represent an additional problem for recovering by waterflooding. The influence of faulting and natural fractures within the reservoir formation will cause high flow zones of fluid migration. This will lead to the drive fluid to bypass the most of the less permeable oil saturated formation. These “thief” zones require selective plugging before waterflooding can effectively be used.
The fraction of unrecoverable crude oil is typically highest for heavy oils, tar, and large complex hydrocarbons. In the U.S. this residual OIP in old oil wells could be as much as 300 billion barrels of light oil. World-wide, the estimate of unrecoverable oil is 2 trillion barrels. There are an additional 5 trillion barrels of heavy oil, most of which is unrecoverable. Much of this remaining oil is in micro-traps due to capillary forces or adsorbed onto mineral surfaces (irreducible oil saturation) as well as bypassed oil within the rock formation.
Enhanced Oil Recovery
Oil recovery by injection of fluids not normally found in the reservoir is referred to as Enhanced Oil Recovery (EOR). It is a subset of Improved Oil Recovery (IOR), which can include operational strategies such as infill drilling and horizontal drilling. Although it is sometimes referred to as tertiary recovery, it can be implemented along with secondary processes. Many types of EOR have been proposed and used over the years. Technical complexity and the high cost of chemicals have prevented the widespread use of EOR to where it only represents about 10% of total United States oil production.
There have been two major EOR approaches; thermal and non-thermal.
Thermal Processes
Thermal processes work by heating the reservoir rock and the oil to reduce viscosity of the heavy oil. In general, the lower the viscosity of the oil, the better its recovery will be. The most widely used thermal process is steam injection in which the temperature of the reservoir and the remaining oil is increased by heat energy of steam. Hot water may also be used, but it is not as efficient at transferring heat to the oil and rock in the reservoir. Unfortunately, in both processes, most of the heat energy is lost to the surroundings and does not go to heating the oil. In situ combustion of the oil is much more efficient than steam because it only heats the reservoir and not all the pipes and overburden rock. However, in situ combustion is difficult to control and is seldom used. Typically, it requires the energy equivalent of a half a barrel of oil to recover a barrel of oil with a steam injected thermal process. However, this depends on the oil saturation and the configuration of the reservoir. Because most of the energy carried by the steam is given up to the pipes, wall rock, and reservoir, it is best to use only on reservoirs with a high oil content so as to recover as much oil as possible with the steam used to heat the reservoir rock. Generally, thermal methods are used on heavy oil because it reduces the viscosity of the oil and increases the mobility of the oil and the mobility ratio (mobility of displacing fluid to mobility of displaced fluid or oil). Typically, recoveries are in the range of 50 to 60% for a thermal process, but the net energy gain is much less than that because of the large amount of energy needed to make steam.
Non-Thermal Processes
Several non-thermal processes have been experimented with or used over the years. These rely on a combination of reducing the oil viscosity and decreasing the interfacial tension (IFT) between the oil and displacing fluid. Ideally, the mobility of the displacing fluid should not be higher than the oil. The mobility ratio (mobility of displacing fluid over mobility of displaced fluid) should be low. The mobility of the oil can be increased by viscosity reduction and by IFT reduction. As the IFT is decreased, the oil becomes more miscible with the fluid until it becomes one phase and the IFT is zero. This decreases the mobility ratio and increases the oil recovery. Alternatively, the viscosity of the displacing fluid can be increased by adding polymers to “thicken” the liquid. Non-thermal methods require less energy and are best suited for light oil of 100 cp or less. However, most non-thermal methods require considerable laboratory experimentation and process optimization.
Microbial Enhanced Oil Recovery (MEOR)
One special type of EOR technique uses microorganisms such as bacteria and archaea to dislodge the micro-trapped or adsorbed oil from the rock. The goal of this technique, which is known as microbial enhanced oil recovery (MEOR), is to increase oil recovery of the original subsurface hydrocarbons using bacteria rather than the more costly chemical recovery processes. These biological processes typically use microorganisms to achieve similar results as the chemical methods in that they reduce IFT and reduce the mobility ratio of the water drive fluid to oil. Of all the EOR processes, MEOR is presently considered the lowest cost approach, but is generally the least often used. The main reason this biological process is not more widely used, is that it is not always successful or predicable. Furthermore, bacteria in oil wells, pipes and tanks are known to cause problems. In fact, it is believed that high viscosity heavy oil such as oil sands are the result of bacteria consuming the lighter weight petroleum components and leaving behind the high molecular weight fractions which are less readily consumed by the bacteria. Therefore many petroleum engineers see bacteria as a problem, not a solution. In fact, if not used correctly, the growth of bacteria could degrade the oil or increase the hydrogen sulfide concentration in the reservoir.
Numerous microorganisms have been proposed for achieving various microbial objectives in subterranean formations. Early MEOR techniques involved injection of an exogenous microbial population into old and low producing oil wells. The inoculating culture was supplied with nutrients and mineral salts as additives to the water pumped into wells for oil recovery. The development of exogenous microorganisms has been limited by the conditions that prevail in the formation. Physical constraints, such as the small and variable formation pore sizes together with the high temperature, salinity and pressure of fluids in the formation and the low concentration of oxygen in the formation waters severely limit the types and number of microorganisms that can be injected and thrive in the formation. Later, it became apparent that indigenous microbes stimulated by the nutrients were playing the major role in oil recovery. Accordingly, many attempts at biological oil recovery do not inject bacteria at all, but rely on indigenous microorganisms exiting in the extreme environment of the oil reservoir.
Methods of enhanced microbial oil recovery are disclosed, for example, in U.S. Pat. No. 8,316,933 and in U.S. Patent Publication Nos. 20130062053 and 20110268846.
Petroleum reservoirs are generally not uniform in permeability or oil saturation. A common type of oil reservoir will be comprised of high and low permeable layers that vary in oil saturation, type of oil and connectivity to one another. If brine is pumped into injection wells to drive the residual oil toward a production well the fluid flow will be difficult to control. Fluid flows along the path of least resistance, which tends to first sweep the oil from the most permeable zone or the zone with the lowest viscosity resident fluid. These zones then become even more permeable as they fill with lower viscosity fluids as a result of extensive water flooding. This further increases the flow of waterflood brine through these high permeable zones and by-passing the oil saturated strata. Therefore any technology that could selectively plug up these high flow zones would be useful for increasing oil recovery because it would redirect the flow of drive fluid into the oil saturated zones. This is particularly important for heavy or moderately heavy oil wherein the viscosity of the oil is much higher than the waterflood drive fluid.
Microorganisms are believed to achieve increased oil recovery by one or more of the following mechanisms: (a) reducing viscosity by degrading higher molecular weight hydrocarbons, (b) producing carbon dioxide which is dissolved into the remaining in-situ oil, (c) producing organic acids which dissolve cementing materials in the formation thereby creating flow passages, (d) producing surfactants that reduce interfacial tension or (e) physically displacing the oil adhering to particles of sand in the formation. These mechanisms have been proposed, among others, in early U.S. patents and publications. For example, U.S. Pat. No. 2,907,389, Hitzman; U.S. Pat. No. 3,032,472, Hitzman; U.S. Pat. No. 2,660,550, Updegraff, et al. have all reported that many types of bacteria can increase oil recovery by a number of not completely understood mechanisms.
One possible mechanism that has been proposed is the production of biopolymers and biofilms that can decrease permeability of the porous reservoir material so much so that it prevents flow into the affected zone. Many of the natural bacteria indigenous to oil bearing formations are capable of forming biofilms. The ability of bacteria to produce a biofilm is believed to give the bacteria an added survival advantage over non-biofilm formers as a way of controlling its environment and maintaining moisture during dehydrating conditions.
Blocking of the affected zone will redirect the flow of fluids into other regions of the formation which contain unrecovered oil. If this bioplugging occurs in a high water swept zone the decrease in permeability will result in more flow into the oil saturated zone. This redirection of flow can increase oil production. Therefore the use of microorganisms to enhance sweep efficiency in waterfloods has been proposed wherein the microorganisms would plug the most porous portions of the reservoir, thereby reducing the tendency of water to “finger” (move through the porous material in an irregular pattern with some streams of fluid penetrating ahead of others) through the high flow zones of the reservoir and leave oil behind.
Placement of Microbes in the Thief Zones of the Formation
Microorganisms that can be stimulated to plug high flow zones may be indigenous native microorganisms preexisting in the formation. The term “native microorganisms”, as used herein, refers to a variety of microorganisms that naturally exist in the subterranean target site. “Exogenous or injected microorganisms” refers to microorganisms that are grown outside of the subterranean target site and are then introduced into the site. This may include microorganisms that were isolated from the target or other subterranean site and then grown outside of the subterranean site before introduction. In one mode specialized cultures of natural, mutated or microbes genetically altered by methods of genetic engineering may be injected into the reservoir. Naturally-occurring microorganisms are known to exist in oil bearing formations, so that any existing microorganisms in such formations have invaded as contaminants of the water used in waterfloods, or as contaminants of the water in active aquifers underlying the oil bearing formation which invades the formation at some time in its existence. Numerous proposals have been made to introduce microorganisms into oil-bearing formations either to supplement existing microorganisms or to colonize the formation. However, these techniques have been unsuccessful because the microorganisms tend to be filtered out at or near the formation face, resulting in severe flow restriction into the formation, or plugging close to the point of injection. Although the goal of injecting microbes may include plugging the high flow zones or thief zones, it is necessary to penetrate far into the formation to reach the thief zone. Therefore penetration of exogenous microorganisms deep into the formation is an important issue for MEOR that employs exogenous microorganisms.
An early method was high pressure injection to open the reservoir by hydro-fracturing. Bond in U.S. Pat. No. 2,975,835 disclosed a method of fracturing the formation with high pressure fluid containing bacteria to reach the remote portions of the formation. Later when it became apparent that many petroleum containing formations contained dormant microorganisms L. Brown in U.S. Pat. No. 4,475,590 suggested simply injecting nutrients to stimulate indigenous microbes already well distributed throughout the reservoir, but, that are dormant because the bacteria lack of proper nutrients for growth. In another approach, Sheehy in U.S. Pat. No. 4,971,151 disclosed a method of analyzing the type of indigenous microbes to select a nutrient that simulated growth. Nutritionally the oil and formation brine are deficient in usable sources of both nitrogenous- and phosphorus-containing compounds. This lack of nutrients tends to prevent growth of most microorganisms, or at best permits growth at a very slow rate. Since microorganisms require water and are generally holophytic (they require their nutrients in solution), and since crude oil is not miscible with water, growth of microorganisms must take place primarily at the oil-water interface. All necessary elements and water must be present for growth and metabolism to take place. An adequate carbon and energy source is readily available in the reservoir in the form of crude oil, so that if proper nutrients are provided growth of the microorganisms can be stimulated. These two methods are limited to indigenous microorganisms and may be unpredictable and difficult to control.
A factor in the penetration of injected microorganisms is the size and cell surface of the organism being injected. Smaller bacteria may penetrate the formation easier than larger bacteria. Cells making extracellular polymers are more likely to adhere to the rock surface. The spores of different bacteria may be used for injection to penetrate even deeper. Spores penetrate a reservoir formation easier and become lodged in these highly permeable zones. When they are stimulated to grow by a nutrient solution, they will then start to grow that then plugs more pores more effectively and deeper into the formation. Some inventors have disclosed injecting bacterial spores downhole followed by a nutrient solution [see U.S. Pat. Nos. 4,558,739 and 4,799,545. Others have used non-spore forming bacteria that become very small when starved by limiting the nutrients during fermentation. These bacteria do not make biofilms because they are nutrient limited when injected. Later, after they have penetrated deep into the reservoir, the nutrients are injected [see U.S. Pat. No. 4,800,959]. Recently Alsop et al. in U.S. Patent Application Publication Number 20120273189 disclosed that a nutrient mixture containing lactate could prevent biofilm formation at the injection well and that a later change to acetate could promote biofilm formation in certain select bacteria as a means for delaying the production of biofilm for bioplugging.
There are a number of methods known in the art that utilize the biomass of the bacteria and the biofilm produced by the bacteria as effective means for closing off zones of high permeability and thereby changing it to a very low permeability zone. However, none of these methods are able to control bacteria to produce cell free or soluble polymer that is not attached to the bacteria cells and that can flow with the drive fluid and increase its viscosity as it moves into the oil saturated zone, without the formation of plugging biofilm. In this mode it is preferred that none of the microorganisms in the reservoir formation produce a plugging biofilm that could restrict the flow of the waterflood drive fluid into the oil saturated zone. Also in the preferred mode, the native bacteria are prevented from producing a biofilm that sequesters the soluble extracellular polymers produced by the exogenous microorganisms into the biofilm.